BONTERRA ENERGY REPORTS SECOND QUARTER AND SIX MONTHS ENDED JUNE 30, 2018 FINANCIAL AND OPERATING RESULTS

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1 For the Six Months ended TSX: BNE BONTERRA ENERGY REPORTS SECOND QUARTER AND SIX MONTHS ENDED JUNE 30, FINANCIAL AND OPERATING RESULTS HIGHLIGHTS As at and for the periods ended ($ 000s except for $ per share and $ per BOE) Three months ended Six months ended FINANCIAL Revenue - realized oil and gas sales 67,458 52, , ,025 Funds flow (1) 37,642 28,508 65,601 53,751 Per share - basic and diluted Dividend payout ratio 27% 35% 30% 37% Cash flow from operations 31,908 27,370 61,785 51,910 Per share - basic and diluted Dividend payout ratio 31% 37% 32% 38% Cash dividends per share Net earnings (loss) 8,925 2,978 12,320 3,453 Per share - basic and diluted Capital expenditures, net of dispositions 18,970 19,416 55,138 49,545 Total assets 1,147,501 1,173,936 Working capital deficiency 27,069 29,759 Long-term debt 303, ,070 Shareholders' equity 503, ,844 OPERATIONS Oil -barrels per day 8,743 8,287 8,391 7,912 -average price ($ per barrel) NGLs -barrels per day average price ($ per barrel) Natural gas - MCF per day 25,317 24,138 25,011 23,196 - average price ($ per MCF) Total barrels of oil equivalent per day (BOE) (2) 13,946 13,153 13,501 12,606 (1) Funds flow is not a recognized measure under IFRS. For these purposes, the Company defines funds flow as funds provided by operations including proceeds from sale of investments and investment income received excluding the effects of changes in non-cash working capital items and decommissioning expenditures settled. (2) BOE may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. 1 P a g e

2 REPORT TO SHAREHOLDERS Oil prices in the second quarter of continued to be volatile, however there are currently indications that a higher base price has been established. After a strong rally in the first quarter, followed by continued strengthening in the second quarter and assuming the rally continues for the remainder of, the broader energy sector will have allocation decisions to make based on available free cash flow. For now Bonterra will continue to allocate free cash flow to debt reduction. The current quarter was one of Bonterra s strongest in recent history, as evidenced by an increase in production to just under 14,000 BOE per day, strong funds flow of $37.6 million, positive net earnings of $8.9 million and the generation of free cash flow all of which continues to improve the Company s financial strength. Bonterra realized strong netbacks in the second quarter mainly due to higher WTI and natural gas liquids ( NGLs ) benchmark pricing coupled with an advantageous foreign exchange rate for USD/CAD. The Company remains focused on being a lowcost producer, with industry-low decline rates and a large inventory of economic undrilled locations that will support its sustainability model for many years into the future. By being consistent with financial and operational practices over the past few years through challenging commodity markets, Bonterra is well positioned to continue executing on our strategy while taking steps to improve balance sheet flexibility. The Company maintains a strategic advantage due to its attractive, high-netbacks per BOE, and a Cardium-focused asset base which requires less than 50 percent of overall funds flow to maintain existing production volumes. The balance of funds flow can continue to be directed towards paying dividends to shareholders and reducing debt to a level that is more in line with industry peers. In the event the Company is able to further lower debt levels due to continued favourable oil prices, it may elect to increase capital expenditures to grow production volumes, take a measured approach to increasing the dividend over time, introduce a share buyback plan or a combination of these options. Bonterra is very pleased with its strong financial and operational results during the second quarter of, with highlights that include: Funds flow of $37.6 million, or $1.13 per share, a 32 percent increase compared to Q2. Outlook Quarterly production of 13,946 BOE per day, six percent higher than Q2 volumes of 13,153 BOE per day and seven percent higher than Q1. Capital expenditures of approximately $19 million, representing approximately 25 percent of the $75 million capital budget for the year. Bonterra anticipates the majority of the remaining capital budget to be spent in the third quarter. Cash netbacks of $30.06 per BOE compared to $23.81 per BOE in Q1 and $23.84 in Q2, representing a 26 percent increase over both periods. Production costs of $13.01 per BOE, 10 percent lower than the $14.49 per BOE in Q1. Realized a 31 percent higher average Canadian crude oil price of $76.51 per barrel in Q2 over Q2, and a 21 percent higher average overall price of $53.15 per BOE in Q2 relative to the same period in. Net debt of $330.5 million, approximately $8.1 million lower than the Q1 ending net debt level of $338.6 million and $40.3 million less than the $370.8 million at the end of Q2. Net earnings of $8.9 million compared to net earnings of $3.0 million for Q2. Continued stable monthly cash dividend payments to shareholders, which represented a dividend payout ratio of 27 percent of funds flow. Global oil prices have seen a healthy recovery over the past two quarters which has contributed to energy companies posting improved results and stronger project economics. Global demand growth has increased by approximately 1.5 million barrels per day and is now approximately 100 million barrels per day and remains strong. Global supply was 2 P a g e

3 also reduced in when OPEC and Russia decided to reduce their production volumes by as much as 1.4 million barrels per day. This supply/demand imbalance is one of the main factors in the recent oil price increase. The forward price outlook for oil and NGLs remains encouraging for the remainder of the year and into Bonterra is uniquely positioned with approximately 94 percent of Company revenue stemming from light oil and NGLs production. The Canadian natural gas markets continue to be challenging; ongoing issues due to a lack of sufficient take away capacity and a supply glut across much of North America has caused severe price deterioration. Since Bonterra has successfully established firm service transportation commitments on approximately 90 percent of its natural gas production, it has actively mitigated some of these challenges. Regardless, a key focus for the energy industry needs to be the continued sanctioning and building of additional pipelines and transportation options for the benefit of all Canadians. Bonterra has maintained a focus on serving shareholders by remaining patient, focusing on the long term, and generating steady funds flow, in order to continue to pay a meaningful dividend on a monthly basis. The Company provides exposure to a low-cost, oil-weighted producer with one of the lowest production decline rates in the industry at approximately 22 percent. Shareholders benefit from upside exposure to the Pembina Cardium pool, and a large inventory of low-risk, highly economic undrilled locations which enhance sustainability and the future outlook for the Company. With ongoing conservative management of the business coupled with the strengthening in oil prices, Bonterra is well positioned to grow production, reserves and funds flow, translating into further value creation for all shareholders. Bonterra s Board of Directors is pleased to welcome Mr. Dan Reuter, Managing Director of Oberndorf Enterprises, a significant shareholder of Bonterra, to the Board effective August 8,. Mr. Reuter brings a wealth of knowledge regarding capital allocation, strategy and corporate governance matters, as well as valuable insights into U.S. institutional shareholder perspectives. For the balance of, Bonterra anticipates that approximately 94 percent of revenue will be derived from crude oil and NGLs, which positions the Company to take advantage of the improving commodity price environment. Depending on commodity prices, the Company remains on target to meet annual production guidance of 13,200 to 13,500 BOE per day while targeting a net debt to funds flow ratio in a range between 2.1 to 2.5 times at year end. Thank you once again for your continued support and loyalty. George F. Fink Chief Executive Officer and Chairman of the Board 3 P a g e

4 MANAGEMENT S DISCUSSION AND ANALYSIS The following report dated August 8, is a review of the operations and current financial position for the six months ended for Bonterra Energy Corp. ( Bonterra or the Company ) and should be read in conjunction with the unaudited condensed financial statements and the audited financial statement including the notes related thereto for the fiscal year ended December 31, presented under International Financial Reporting Standards (IFRS). Use of Non-IFRS Financial Measures Throughout this Management s Discussion and Analysis (MD&A) the Company uses the terms payout ratio, cash netback and net debt to analyze operating performance, which are not standardized measures recognized under IFRS and do not have a standardized meaning prescribed by IFRS. These measures are commonly used in the oil and gas industry and are considered informative by management, shareholders and analysts. These measures may differ from those made by other companies and accordingly may not be comparable to such measures as reported by other companies. The Company calculates payout ratio percentage by dividing cash dividends paid to shareholders by cash flow from operating activities, both of which are measures prescribed by IFRS which appear on our statements of cash flows. We calculate cash netback by dividing various financial statement items as determined by IFRS by total production for the period on a barrel of oil equivalent basis. The Company calculates net debt as long-term debt plus working capital deficiency (current liabilities less current assets). Frequently Recurring Terms Bonterra uses the following frequently recurring terms in this MD&A: WTI refers to West Texas Intermediate, a grade of light sweet crude oil used as benchmark pricing in the United States; MSW Stream Index or Edmonton Par refers to the mixed sweet blend that is the benchmark price for conventionally produced light sweet crude oil in Western Canada; AECO refers to Alberta Energy Company, a grade or heating content of natural gas used as benchmark pricing in Alberta, Canada; bbl refers to barrel; NGL refers to Natural gas liquids; MCF refers to thousand cubic feet; MMBTU refers to million British Thermal Units; GJ refers to gigajoule; and BOE refers to barrels of oil equivalent. Disclosure provided herein in respect of a BOE may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Numerical Amounts The reporting and the functional currency of the Company is the Canadian dollar. 4 P a g e

5 QUARTERLY COMPARISONS As at and for the periods ended ($ 000s except $ per share) Q2 Q1 Q4 Q3 Q2 Q1 Financial Revenue - oil and gas sales 67,458 57,124 54,192 46,349 52,695 49,330 Cash flow from operations 31,908 29,877 26,472 25,491 27,370 24,540 Per share - basic and diluted Payout ratio 31% 33% 38% 40% 37% 41% Cash dividends per share Net earnings (loss) 8,925 3,395 2,096 (3,043) 2, Per share - basic and diluted (0.09) Capital expenditures 18,970 36,168 18,775 (1) 14,121 19,416 30,129 Disposition ,752 (1) Total assets 1,147,501 1,142,670 1,125,551 1,146,498 1,173,936 1,156,398 Working capital deficiency 27,069 46,630 27,790 28,260 29,759 39,483 Long-term debt 303, , , , , ,118 Shareholders' equity 503, , , , , ,742 Operations Oil (barrels per day) 8,743 8,034 7,766 8,038 8,287 7,533 NGLs (barrels per day) , Natural gas (MCF per day) 25,317 24,701 24,466 25,460 24,138 22,243 Total BOE per day 13,946 13,051 12,807 13,281 13,153 12,053 (1) For Q4, includes the Disposition of a two percent overriding royalty interest on the total production from the Company s Pembina Cardium pool that closed December 20, and is effective January 1,. Consideration consisted of $52 million of cash and incremental Cardium assets valued at $4.7 million which is included in capital expenditures (refer to Note 5 of the December 31, audited annual financial statements). 5 P a g e

6 As at and for the periods ended ($ 000s except $ per share) Q4 Q3 Q2 Q1 Financial Revenue - oil and gas sales 48,967 46,236 41,150 33,510 Cash flow from operations 31,537 19,219 13,392 11,146 Per share - basic and diluted Dividend payout ratio 32% 52% 75% 89% Cash dividends per share Net loss (1,168) (5,830) (5,582) (11,555) Per share - basic and diluted (0.03) (0.18) (0.17) (0.35) Capital expenditures, net of dispositions 12,270 17,424 9,420 1,683 Total assets 1,147,834 1,163,743 1,169,782 1,174,141 Working capital deficiency 24,921 26,361 18,429 13,115 Long-term debt 329, , , ,118 Shareholders' equity 543, , , ,925 Operations Oil (barrels per day) 7,467 8,197 7,780 8,325 NGLs (barrels per day) Natural gas (MCF per day) 22,540 24,948 21,771 22,274 Total BOE per day 12,134 13,298 12,285 12, Business Environment and Sensitivities Bonterra s financial results are significantly influenced by fluctuations in commodity prices, including price differentials and foreign exchange. The following table depicts selective market benchmark prices, differentials and foreign exchange rates in the last eight quarters to assist in understanding volatility in prices and foreign exchange rates that have impacted Bonterra s financial and operating performance. The increases or decreases for Bonterra s realized price for oil and natural gas for each of the eight quarters is also outlined in detail in the following table. Q2- Q1- Q4- Q3- Q2- Q1- Q Q Crude oil WTI (U.S.$/bbl) WTI to MSW Stream Index Differential (U.S.$/bbl) (1) (5.45) (5.89) (1.14) (2.89) (2.26) (3.60) (3.09) (3.02) Foreign exchange U.S.$ to Cdn$ Bonterra average realized oil price (Cdn$/bbl) Natural gas AECO (Cdn$/mcf) Bonterra average realized gas price (Cdn$/mcf) (1) This differential accounts for the major difference between WTI and Bonterra s average realized price (before quality adjustments and foreign exchange). 6 P a g e

7 The overall volatility in Bonterra s average realized commodity pricing can be impacted by numerous events or factors, including but not limited to: Worldwide crude oil supply and demand imbalance; Geo-political events that affect worldwide crude oil supply and demand; The value of the Canadian dollar compared to the US dollar; Access to infrastructure and markets; Weather; and Timing and duration of plant, refinery and pipeline maintenance. WTI benchmark pricing which has been steadily increasing from the low of $30.62 US per bbl in February of 2016, continued to increase in the first half of, and is currently trading around $70.00 US per barrel. This price increase has been attributed to reductions in global crude oil inventories and increased global demand. In June OPEC agreed to ease restrictions that were placed on its members production in This was done to offset anticipated reductions in production from Venezuela, and Iran. Globally, supply and demand are expected to remain tight through the second half of. In June of, Syncrude experienced a full plant outage taking upwards of 300,000 barrels per day of production off line in Western Canada. This has helped to ease local transportation and storage bottlenecks and as a result, realized differentials for Western Canadian crude have been slightly better than forecast. Recent political and regulatory events should have a positive impact on two pipeline projects for Western Canadian crude. It s anticipated that construction will commence on the TransMountain pipeline expansion early in 2019 and the final segment of Enbridge s Line 3 expansion in the 2nd half of. Expanding export capacity by increasing capacity on existing lines or completion of any of the pipeline expansion projects may have a positive effect on the movement and pricing of Canadian barrels. The AECO benchmark price for natural gas declined in the second quarter of. This was mainly due to lower intra provincial demand as heating loads decreased with the transition into spring, as well as reduced pipeline capability as TransCanada Pipeline implemented capacity restrictions as necessary to commence annual maintenance activities. Western Canadian supply continues to hover near historically high levels. Should this continue throughout, pipeline infrastructure will struggle to handle the existing and incremental volumes. Increasing demand for heating and electricity should result in better pricing moving into fall and winter. The following chart shows the Company s sensitivity to key commodity price variables. The sensitivity calculations are performed independently and show the effect of changing one variable while holding all other variables constant. Annualized sensitivity analysis on cash flow, as estimated for (1) Impact on cash flow Change ($) $000s $ per share (2) Realized crude oil price ($/bbl) , Realized natural gas price ($/mcf) U.S.$ to Canadian $ exchange rate , (1) This analysis uses current royalty rates, annualized estimated average production of 13,200 BOE per day and no changes in working capital (2) Based on annualized basic weighted average shares outstanding of 33,310,796 Business Overview, Strategy and Key Performance Drivers Bonterra s second quarter results improved compared to the first quarter of primarily due to an increase in production volumes from its high quality, oil-weighted assets in the Pembina Cardium area of Alberta. The increase in production was due to the Company s accelerated capital and well maintenance programs during Q1. During the first six months of, fourteen of the eighteen operated wells were placed on production in the first quarter, along with reactivating down wells by employing four service rigs from the usual two service rigs during the same period. Having a full quarter of production from the wells drilled in the first quarter and previous down wells, resulted in Bonterra s production increasing by 895 BOE per day in Q2 to 13,946 BOE per day from Q1. 7 P a g e

8 During Q1 the Company accelerated the capital program and well maintenance programs to maximize production before lease accessibility decreased due to spring breakup. As a result, the Company has spent $55,138,000 in the first six months of of its $75,000,000 annual capital budget with approximately $36,200,000 spent in the first quarter. Approximately $47,564,000 was spent to drill 20 gross operated (19.9 net) wells and complete, equip and tie-in 18 gross (17.9 net) wells, of which two gross (2.0 net) were placed on production in July. The remaining $7,574,000 was incurred on infrastructure and non-operated wells. Bonterra plans to spend most of its remaining annual capital budget in the third quarter. The Company will review its annual capital guidance and consider if additional capital will be spent in the fourth quarter, beyond the $75,000,000 budgeted. In the second quarter to protect the cashflow generated by the capital and maintenance programs, the Company entered into physical delivery sales contracts for a portion of its production. These contracts provided an average minimum WTI base price for oil of $57.51 US per bbl on 2,500 bbl per day and an average minimum base price for natural gas of $0.80 per GJ on 5,000 GJ per day (approximately 30 percent of the oil production and 20 percent of the gas production respectively). The Company currently has no physical delivery sales contracts in place. On April 30, the Company renewed its bank facility at $380,000,000 under similar terms and conditions. The bank facility is comprised of a $330,000,000 syndicated revolving credit facility, and a $50,000,000 non-syndicated revolving credit facility. The revolving period on the bank facility expires on April 29, 2019, with a maturity date of April 30, 2020, subject to an annual review. As at, Bonterra had $303,413,000 ( - $341,070,000) drawn on the $380,000,000 bank facility. These credit facilities provide the Company with sufficient liquidity and financial flexibility to execute its business plan. With the additional cash flow from the new wells added, primarily in the first quarter, the Company was able to reduce net debt by $8,142,000 in the second quarter compared to the first quarter of. The Company averaged 13,501 BOE per day for the first six months of. Although Bonterra has done extensive work to optimize production by bringing new wells on production and reactivating down wells early in the year, the Company expects Q3 production to be less than Q2 production of 13,946 BOE per day due to major facility turnarounds required at two of the larger oil batteries and a wholly owned gas plant in the month of July for up to seven days. However, the Company maintains its annual production guidance of 13,200 to 13,500 BOE per day. Bonterra s successful operations are dependent upon several factors including, but not limited to: commodity prices, efficient management of capital spending, monthly dividends, ability to maintain desired levels of production, control over infrastructure, efficiency in developing and operating properties, and the ability to control costs. The Company s key measures of performance with respect to these drivers include but are not limited to: average production per day, average realized prices, and average operating costs per unit of production. Disclosure of these key performance measures can be found in the MD&A and/or previous interim or annual MD&A disclosures. Drilling Three months ended March 31, Six months ended Gross (1) Net (2) Gross (1) Net (2) Gross (1) Net (2) Gross (1) Net (2) Gross (1) Net (2) Crude oil horizontal-operated Crude oil horizontal-non-operated Total Success rate 100% 100% 100% 100% 100% (1) Gross wells means the number of wells in which Bonterra has a working interest. (2) Net wells means the aggregate number of wells obtained by multiplying each gross well by Bonterra s percentage of working interest. During the first six months of, the Company drilled 20 gross (19.9 net) wells, of which 18 gross (17.9 net) wells were completed, equipped, tied-in and placed on production. The remaining two wells were brought on production in July. In addition, two gross (0.2 net) non-operated wells were drilled, completed, equipped and on production during the first quarter of. 8 P a g e

9 Production Three months ended Six months ended March 31, Crude oil (barrels per day) 8,743 8,034 8,287 8,391 7,912 NGLs (barrels per day) Natural gas (MCF per day) 25,317 24,701 24,138 25,011 23,196 Average BOE per day 13,946 13,051 13,153 13,501 12,606 The second quarter yielded a very positive impact on production volumes for the first six months of compared to the first six months of and Q2 over Q1. With increased crude oil prices, Bonterra placed a strong focus to bringing new wells on production early in the first six months of the year before spring breakup. As a result, the Company placed eighteen (17.9 net) wells on production, of which fourteen (13.9 net) wells were on production in Q1 compared to twenty-one (18.1 net) wells, of which only five (3.7 net) wells were on production in Q1. The Company also reactivated more down wells in the first quarter of compared to Q1. Cash Netback The following table illustrates the calculation of the Company s cash netback from operations for the periods ended: Three months ended Six months ended $ per BOE March 31, Production volumes (BOE) 1,269,114 1,174,598 1,196,897 2,443,713 2,281,708 Gross production revenue Royalties (5.45) (4.92) (3.06) (5.19) (3.10) Production costs (13.01) (14.49) (12.27) (13.73) (12.85) Field netback General and administrative (1.67) (1.73) (1.60) (1.70) (1.77) Interest and other (2.96) (3.68) (3.26) (3.31) (3.44) Cash netback Cash netbacks for the first six months of compared to the same period a year ago increased by $3.50 per BOE. This is primarily due to the increase in commodity prices being partially offset by an increase in royalty rates for the two percent gross overriding royalty (GORR) on the Pembina Cardium pool assets effective January 1,. Production costs were higher in Q1 due to adding additional service rigs to repair non-producing wells before spring breakup and to take advantage of the increase in the price of crude oil. Oil and Gas Sales Three months ended March 31, Six months ended Revenue - oil and gas sales ($ 000s) Crude oil 60,869 49,009 44, ,879 85,314 NGL 3,912 3,135 2,081 7,047 4,281 Natural gas 2,677 4,980 6,609 7,657 12,430 67,458 57,124 52, , ,025 Average realized prices: Crude oil ($ per barrel) NGLs ($ per barrel) Natural gas ($ per MCF) Average ($ per BOE) Average BOE per day 13,946 13,051 13,153 13,501 12,606 9 P a g e

10 Revenue from oil and gas sales for the first six months of increased by $22,558,000, or 22 percent, compared to the same period a year ago. The increase in oil and gas sales was primarily driven by higher production and commodity prices for oil and NGLs. The quarter over quarter increase in oil and gas sales was primarily due to increased production volumes and commodity prices for oil and NGLs. The Company s product split on a revenue basis for is approximately 94 percent weighted towards crude oil and NGLs. Royalties Three months ended Six months ended ($ 000s) March 31, Crown royalties 4,090 3,807 2,611 7,897 4,966 Freehold, gross overriding and other royalties 2,820 1,974 1,048 4,795 2,100 Total royalties 6,910 5,781 3,659 12,692 7,066 Crown royalties - percentage of revenue Freehold, gross overriding and other royalties - percentage of revenue Royalties - percentage of revenue Royalties $ per BOE Royalties paid by the Company consist of crown royalties to the Provinces of Alberta, Saskatchewan and British Columbia and non-crown royalties. Total royalties on a per BOE basis increased by $2.09 per BOE for the first half of compared to the same period for. The increase in royalties is primarily due to the two percent GORR transaction on the Pembina Cardium pool assets along with an overall increase in commodity prices. Quarter over quarter increase in royalties of $0.53 per BOE was due to an increase in crude oil and NGL prices. Production Costs Three months ended Six months ended ($ 000s except $ per BOE) March 31, Production costs 16,517 17,026 14,694 33,543 29,319 $ per BOE Production costs for the first six months of increased by $0.88 per BOE compared to the first six months of, primarily due to employing four service rigs instead of two during the first quarter. Adding two additional service rigs allowed Bonterra to reactivate more shut-in wells, to take advantage of higher commodity prices and to avoid pending road bans in the spring. Quarter over quarter production costs decreased by $1.48 due to a reduction of service rig costs and to additional production volumes from wells that were placed on production starting in late March. Other Income Three months ended Six months ended ($ 000s) March 31, Investment income (72) Administrative income Deferred consideration In the fourth quarter of, Bonterra sold a two percent overriding royalty interest on the total production from the Company s Pembina Cardium pool with an effective date of January 1,. Consideration received on disposition 10 P a g e

11 was $56,747,000, comprised of $52,000,000 in cash and property, plant and equipment valued at $4,747,000. The result of this disposition was a gain on disposal of $4,226,000 and deferred consideration of $16,064,000, of which $728,000 was recognized in the first half of. The market value of the investments held by the Company at was $608,000 ( - $1,078,000). The carrying value decreased due to a reduction in the investments carrying value. There were no dispositions for the six months ended or. Dispositions that result in a gain or loss on sale are recorded as an equity transfer between accumulated other comprehensive income and retained earnings. The Company receives administrative income for various oil and gas administrative services and production equipment rentals. General and Administration (G&A) Expense Three months ended Six months ended ($ 000s except $ per BOE) March 31, Employee compensation expense 1,370 1,365 1,058 2,735 2,569 Office and administrative expense ,412 1,466 Total G&A expense 2,117 2,030 1,918 4,147 4,035 $ per BOE The increase of $166,000 in employee compensation expense for the first six months of compared to the same period in is primarily due to a higher bonus accrual from increased earnings before income taxes. The Company has a bonus plan in which the bonus pool consists of a range between 2.5 percent to 3.5 percent of earnings before income taxes. The Company firmly believes that tying employee compensation (including the use of stock options) to corporate performance clearly aligns the interests of the employees with those of shareholders. Finance Costs Three months ended Six months ended ($ 000s except $ per BOE) March 31, Interest on long-term debt 3,504 4,260 3,759 7,764 7,536 Other interest Interest expense 3,721 4,479 3,976 8,200 7,969 $ per BOE Unwinding of the discounted value of decommissioning liabilities ,518 1,489 Total finance costs 4,482 5,236 4,724 9,718 9,458 Interest on long-term debt increased in the first six months of compared to the same period of despite the Company carrying a lower average long-term debt by $38,000,000. The Company realized higher interest rates in based on a trailing net debt to EBITDA ratio from Q3. Interest rates on long-term debt decreased in the second quarter of with a much lower Q4 net debt to EBITDA ratio that came into effect. Interest rates for the current quarter are determined based on the trailing quarter by the ratio of total debt (excluding accounts payable and accrued liabilities) to EBITDA (defined as net income excluding finance costs, provision for current and deferred taxes, depletion and depreciation, share-option compensation, gain or loss on sale of assets and impairment of assets) multiplied by four. Other interest relates to amounts paid to a related party (see related party transactions) and a $10,000,000 subordinated promissory note from a private investor. For more information about the subordinated promissory note, refer to Note 5 of the condensed financial statements. A one percent increase (decrease) in the Canadian prime rate would decrease (increase) both annual net earnings and comprehensive income by approximately $2,303, P a g e

12 Share-Option Compensation Three months ended Six months ended ($ 000s) March 31, Share-option compensation ,239 1,508 2,878 Share-option compensation is a statistically calculated value representing the estimated expense of issuing employee stock options. The Company records a compensation expense over the vesting period based on the fair value of options granted to employees, directors and consultants. Share-option compensation decreased by $1,370,000 from a year ago as the majority of the options issued in 2016, that were fully amortized in had a higher share price volatility than the options issued in the fourth quarter of ; which are amortizing in. Based on the outstanding options as of, the Company has an unamortized expense of $2,061,000, of which $1,059,000 will be recorded for the remainder of, $982,000 for 2019 and $20,000 thereafter. For more information about options issued and outstanding, refer to Note 8 of the condensed financial statements. Depletion and Depreciation, Exploration and Evaluation (E&E) and Goodwill Three months ended Six months ended ($ 000s) March 31, Depletion and depreciation 24,526 21,450 22,535 45,976 44,078 Exploration and evaluation The provision for depletion and depreciation increased for the first six months of compared to the first six months of due to increased production volumes and capital. Quarter over quarter increase in depletion and depreciation is also due to an increase in production volumes. Exploration and evaluation expense related to expired leases. There were no impairment provisions recorded for the three and six months ended and. Taxes The Company recorded income tax expense of $5,237,000 for the first six months of ( $1,865,000). The increase in income tax expense is due to an increase in net earnings before income taxes. Included in current income tax expense is $521,000 ( - $12,000) of provincial income taxes that was recognized and included in accounts payable and accrued liabilities for the six months ended. For additional information regarding income taxes, see Note 7 of the condensed financial statements. Net Earnings Three months ended Six months ended ($ 000s except $ per share) March 31, Net earnings 8,925 3,395 2,978 12,320 3,453 $ per share - basic $ per share - diluted P a g e

13 Net earnings for the first six months of increased by $8,867,000 compared to the first six months of. The increase in net earnings was mainly due to increased commodity prices for oil and NGLs and production volumes. The increase in net earnings was partially offset by an increase in royalties, production costs and income tax expense. The quarter over quarter increase in net earnings was mainly due to an increase in oil and gas sales and a decrease in production costs, which was partially offset by an increase in depletion and depreciation and income tax expense. Other Comprehensive Income (Loss) Other comprehensive income for consists of an unrealized loss before tax on investments (including investment in a related party) of $142,000 relating to a decrease in the investments fair value ( unrealized loss of $543,000). Realized gains decrease accumulated other comprehensive income as these gains are transferred to retained earnings. Other comprehensive income varies from net earnings by unrealized changes in the fair value of Bonterra s holdings of investments including the investment in a related party, net of tax. Cash Flow from Operations Three months ended Six months ended ($ 000s except $ per share) March 31, Cash flow from operations 31,908 29,877 27,370 61,785 51,910 $ per share - basic $ per share - diluted In the first half of, cash flow from operations increased by $9,875,000 compared to the same period a year ago. This was primarily due to an increase in revenue from oil and gas sales. The increase in cash flow was partially offset by an increase in royalties and production costs. The quarter over quarter increase in cash flow of $2,031,000 is primarily due to an increase in revenue from oil and gas sales, which was partially offset by an increase in royalties and a decrease in non-cash working capital. Related Party Transactions Bonterra holds 1,034,523 (December 31, 1,034,523) common shares in Pine Cliff Energy Ltd. ( Pine Cliff ) which represents less than one percent ownership in Pine Cliff s outstanding common shares. Pine Cliff s common shares had a fair market value as of of $367,000 (December 31, of $476,000). The Company provides executive and marketing services for Pine Cliff. All services that were performed were charged at estimated fair value. As at, the Company had an account receivable from Pine Cliff of $31,000 (December 31, $36,000). As at, the Company s CEO, Chairman of the Board and a major shareholder has loaned the Company $12,000,000 (December 31, - $12,000,000). The loan bears interest at Canadian chartered bank prime less 5/8 th of a percent and has no set repayment terms but is payable on demand. Security under the debenture is over all of the Company s assets and is subordinated to any and all claims in favour of the syndicate of senior lenders providing credit facilities to the Company. The Company s bank agreement requires that the above loan can only be repaid should the Company have sufficient available borrowing limits under the Company s credit facility. Interest paid on this loan for the first six months of was $167,000 ( - $123,000). This loan results in a substantial benefit to Bonterra as the interest paid to the CEO by Bonterra is lower than bank interest. Liquidity and Capital Resources Net Debt to Cash Flow from Operations Bonterra continues to focus on monitoring overall debt while managing its cash flow, capital expenditures and dividend payments. The Company s net debt to twelve-month trailing cash flow ratio as of was 2.9 to 1 times (versus 3.1 to 1 times at December 31, ). The reduction in net debt to cash flow ratio is primarily due to an increase in cash flow that was partially offset by an increase in net debt from spending approximately half of the 13 P a g e

14 Company s $75,000,000 capital budget in the first quarter of. The Company incurred an $8,142,000 reduction in net debt in the second quarter due to increased cash flow from new wells and less capital spent compared to the first quarter. The Company s primary focus is to manage its bank debt during a period of volatile commodity prices. The Company will continue to assess its dividend and capital expenditures compared to cash flow from operations on a quarterly basis. Working Capital Deficiency and Net debt ($ 000s) March 31, December 31, Working capital deficiency 27,069 46,630 27,790 29,759 Long-term bank debt 303, , , ,070 Net Debt 330, , , ,829 The Company has sufficient availability on its credit facility to repay both the related party loan and the subordinated promissory note if required. During each quarter, the Company manages net debt by monitoring capital spending and dividends paid compared to cash flow from operations. Net debt is a combination of long-term bank debt and working capital. Net debt for decreased by $40,347,000 from primarily due to the $52,000,000 received for the GORR transaction in the fourth quarter of and increased cash flow from higher commodity prices partially offset by higher capital spending in the first quarter. Quarter over quarter net debt decreased by $8,142,000 due to increased cash flow from increased production and commodity prices and less capital spending compared to Q1. Working capital is calculated as current liabilities less current assets. The Company finances its working capital deficiency using cash flow from operations, its long-term bank facility, share issuances, option exercises, sale of noncore assets and investments and adjustments of dividend payments. Included in the working capital deficiency at is $22,000,000 million of debt relating to the subordinated promissory note and the amount due to a related party. Financial Risk Management The Company has entered into physical delivery sales contracts to manage commodity risk. These contracts are considered normal sales contracts and are not recorded at fair value in the financial statements. For more information on physical delivery contracts in place see Note 10 of the condensed financial statements. Capital Expenditures During the six months ended, the Company incurred capital expenditures of $55,138,000 ( - $49,545,000). The costs relate to drilling 20 gross (19.9 net) wells with related infrastructure costs, of which 18 gross (17.9 net) wells were completed, equipped, tied-in and placed on production. The remaining two wells were brought on production in July of. In addition, two gross (0.2 net) non-operated well was drilled, completed, equipped and on production during the first six months of. Liability Management Ratio ( LMR ) Update In the first six months of, 94.5 percent of the Company s production is from the province of Alberta. The Company currently has an LMR rating of 2.10 in Alberta and does not expect that with its current LMR there will be any regulatory impediments to completing future potential acquisitions. Long-term Debt Long-term debt represents the outstanding draws from the Company s bank facility as described in the notes to the Company s audited annual financial statements. As of, the Company has a bank facility with a limit of $380,000,000 (December 31, - $380,000,000) that is comprised of a $330,000,000 syndicated revolving credit facility and a $50,000,000 non-syndicated revolving credit facility. Amounts drawn under this bank facility at 14 P a g e

15 totaled $303,413,000 (December 31, - $292,212,000). The interest rates for the six months ended on the Company s Canadian prime rate loan and Banker s Acceptances are between four to six percent. The loan is revolving to April 29, 2019 with a maturity date of April 30, 2020, subject to annual review. The credit facilities have no fixed terms of repayment. The available lending limits of credit facilities are reviewed semi-annually on or before April 30 and October 31 each year based mainly on the lender s assessment of the Company s reserves, future commodity prices and costs. Advances drawn under the bank facility are secured by a fixed and floating charge debenture over the assets of the Company. In the event the bank facility is not extended or renewed, amounts drawn under the facility would be due and payable on the maturity date. The size of the committed credit facilities is based primarily on the value of the Company s producing petroleum and natural gas assets and related tangible assets as determined by the lenders. For more information see Note 6 of the condensed financial statements. Shareholders Equity The Company is authorized to issue an unlimited number of common shares without nominal or par value. The Company is authorized to issue an unlimited number of Class A redeemable Preferred Shares and an unlimited number of Class B Preferred Shares. There are currently no outstanding Class A redeemable Preferred Shares or Class B Preferred Shares. Amount Issued and fully paid - common shares Number ($ 000s) Balance, and December 31, 33,310, ,977 The Company provides a stock option plan for its directors, officers, employees and consultants. Under the plan, the Company may grant options for up to 3,331,080 (December 31, 3,331,080) common shares. The exercise price of each option granted will not be lower than the market price of the common shares on the date of grant and the option s maximum term is five years. For additional information regarding options outstanding, see Note 8 of the June 30, condensed financial statements. Dividend Policy For the three months ended, the Company declared and paid dividends of $9,993,000 ($0.30 per share) ( $9,993,000) ($0.30 per share). For the six months ended the Company declared and paid dividends of 19,986,000 ($0.60 per share) ( - $19,985,000 ($0.60 per share)). Bonterra s dividend policy is regularly monitored and is dependent upon production, commodity prices, cash flow from operations, debt levels and capital expenditures. With its large inventory of undrilled locations, Bonterra continues to be well positioned to provide its shareholders with a combination of sustainable growth and meaningful dividend income. Bonterra s dividend payout ratio based on cash flow from operations was 32 percent for the six months ended June 30, (38 percent for the six months ended ). Bonterra s dividends to its shareholders are funded by cash flow from operating activities with the remaining cash flow directed to capital spending and debt repayment. To the extent that the excess cash flow from operations after dividends is not sufficient to cover capital spending, the shortfall is funded by drawdowns on Bonterra s bank facility. Bonterra intends to provide dividends to shareholders that are sustainable by the Company with consideration to its liquidity and long-term operational strategy. The level of dividends is highly dependent upon cash flow generated from operations, which may fluctuate significantly due to changes in financial and operational performance, commodity prices, interest and exchange rates and many other factors; as such future dividends cannot be assured. 15 P a g e

16 Quarterly Financial Information For the periods ended ($ 000s except $ per share) Q2 Q1 Q4 Q3 Q2 Q1 Revenue - oil and gas sales 67,458 57,124 54,192 46,349 52,695 49,330 Cash flow from operations 31,908 29,877 26,472 25,491 27,370 24,540 Net earnings (loss) 8,925 3,395 2,096 (3,043) 2, Per share - basic (0.09) Per share - diluted (0.09) For the periods ended ($ 000s except $ per share) Q4 Q3 Q2 Q1 Revenue - oil and gas sales 48,967 46,236 41,150 33,510 Cash flow from operations 31,537 19,219 13,392 11,146 Net loss (1,168) (5,830) (5,582) (11,555) Per share - basic (0.03) (0.18) (0.17) (0.35) Per share - diluted (0.03) (0.18) (0.17) (0.35) The fluctuations in the Company s revenue and net earnings from quarter to quarter are caused by variations in production volumes, realized commodity pricing and the related impact on royalties, production, G&A and finance costs. In the first and second quarters of 2016, net earnings and cash flow were lower than most other periods due to a significant decrease in commodity prices. Critical Accounting Estimates There have been no changes to the Company s critical accounting policies and estimates as of the period ended in the financial statements. Forward-Looking Information Certain statements contained in this MD&A include statements which contain words such as anticipate, could, should, expect, seek, may, intend, likely, will, believe and similar expressions, relating to matters that are not historical facts, and such statements of our beliefs, intentions and expectations about development, results and events which will or may occur in the future, constitute forward-looking information within the meaning of applicable Canadian securities legislation and are based on certain assumptions and analysis made by us derived from our experience and perceptions. Forward-looking information in this MD&A includes, but is not limited to: expected cash provided by continuing operations; cash dividends; future capital expenditures, including the amount and nature thereof; oil and natural gas prices and demand; expansion and other development trends of the oil and gas industry; business strategy and outlook; expansion and growth of our business and operations; and maintenance of existing customer, supplier and partner relationships; supply channels; accounting policies; credit risks; and other such matters. All such forward-looking information is based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate in the circumstances. The risks, uncertainties, and assumptions are difficult to predict and may affect operations, and may include, without limitation: foreign exchange fluctuations; equipment and labour shortages and inflationary costs; general economic conditions; industry conditions; changes in applicable environmental, taxation and other laws and regulations as well as how such laws and regulations are interpreted and enforced; the ability of oil and natural gas companies to raise capital; the effect of weather conditions on operations and facilities; the existence of operating risks; volatility of oil and natural gas prices; oil and gas product supply and demand; risks inherent in the ability to generate sufficient cash flow from operations to meet current and future obligations; increased competition; stock market volatility; opportunities available to or pursued by us; and other factors, many of which are beyond our control. The foregoing factors are not exhaustive. 16 P a g e

17 Actual results, performance or achievements could differ materially from those expressed in, or implied by, this forward-looking information and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking information will transpire or occur, or if any of them do, what benefits will be derived therefrom. Except as required by law, Bonterra disclaims any intention or obligation to update or revise any forward-looking information, whether as a result of new information, future events or otherwise. The forward-looking information contained herein is expressly qualified by this cautionary statement. Internal Controls Over Financial Reporting The Company is required to comply with National Instrument Certification of Disclosure in Issuers Annual and Interim Filings. The certification of interim filings for the interim period ended requires that Bonterra disclose in the interim MD&A any changes in the Company s internal control over financial reporting that occurred during the period that have materially affected, or are reasonably likely to materially affect, the Company s internal control over financial reporting. Bonterra confirms that no such changes were made to its internal controls over financial reporting during the six months ended. Additional information relating to the Company may be found on or visit our website at 17 P a g e